via electronic case filing ms. kavita kale executive ...ms. kavita kale executive secretary michigan...

Clark Hill PLC

151 S. Old Woodward

Suite 200

Birmingham, MI 48009

Robert A. W. Strong T 248.642.9692

T 248.988.5861 F 248.642.2174F 248.988.2323

Email: [email protected] clarkhill.com

216768428.1 07411/319492

January 12, 2018

VIA ELECTRONIC CASE FILINGMs. Kavita KaleExecutive SecretaryMichigan Public Service Commission7109 West Saginaw HighwayLansing, Michigan 48917

Re: MPSC Case No. U-18419: In the matter of the application of DTE ElectricCompany for approval of Certificates of Necessity pursuant to MCL 460.6s,as amended, in connection with the addition of a natural gas combined cyclegenerating facility to its generation fleet and for related accounting andratemaking authorizations

Dear Ms. Kale:

Enclosed for filing are the Direct Testimony and Exhibits of Nicholas L. Phillips onbehalf of ABATE, along with a Proof of Service in the case referenced above.

Very truly yours,

CLARK HILL PLC

Robert A. W. Strong

RAWS:lllm

cc w/enc: Parties of Record

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application ofDTE ELECTRIC COMPANY forapproval of Certificates ofNecessity pursuant to MCL 460.6s,as amended, in connection withthe addition of a natural gascombined cycle generating facilityto its generation fleet and forrelated accounting andratemaking authorizations.

))))))))))))

Case No. U-18419

Direct Testimony and Exhibits of

Nicholas L. Phillips

On behalf of

Association of Businesses Advocating Tariff Equity

January 12, 2018

Project 10481

Nicholas L. PhillipsPage 1

STATE OF MICHIGAN


In the matter of the Application ofDTE ELECTRIC COMPANY forapproval of Certificates ofNecessity pursuant to MCL 460.6s,as amended, in connection withthe addition of a natural gascombined cycle generating facilityto its generation fleet and forrelated accounting andratemaking authorizations.

))))))))))))

Case No. U-18419

Direct Testimony of Nicholas L. Phillips

Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.1

A Nicholas L. Phillips. My business address is 16690 Swingley Ridge Road, Suite 140,2

Chesterfield, MO 63017.3

Q WHAT IS YOUR OCCUPATION?4

A I am a consultant in the field of public utility regulation and an Associate with the firm5

of Brubaker & Associates, Inc. (“BAI”), energy, economic and regulatory consultants.6

Q ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING?7

A I am appearing on behalf of the Association of Businesses Advocating Tariff Equity8

(“ABATE”). ABATE’s members are customers of DTE Electric Company (“DTE” or9

“Company”).10


Q ARE YOU FAMILIAR WITH THE FILING IN THIS DOCKET?1

A Yes. I have reviewed the application, testimony and exhibits that have been filed. In2

addition, I have reviewed the responses to numerous data requests submitted by3

ABATE, the Staff of the Michigan Public Service Commission (“MPSC” or4

“Commission”), and numerous other intervenors.5

Q WHAT IS DTE REQUESTING IN THIS DOCKET?6

A DTE is seeking Certificates of Necessity (“CON”) in connection with the7

Company’s proposal to build a nominal 1,100 MW natural gas combined cycle8

(“CCGT”) generating facility at the Company’s Belle River Power Plant site9

(“Proposed Project” or “Belle River CCGT”).10

Q WHAT HAVE YOU FOUND FROM YOUR ANALYSIS OF DTE’S REQUEST?11

A The foundation of DTE’s request for a CON is predicated upon its proposal to retire12

the River Rouge, St. Clair, and the Trenton Channel coal-fired generating units before13

December 2023.1 The retirement of this capacity creates the need for additional14

capacity resources which DTE proposes to meet by constructing and operating the15

Proposed Project. However, the retirement analysis itself was conducted in early16

2016 and contains assumptions which relate to federal environmental and tax policies17

that are no longer valid.218

Q WHAT ARE YOUR RECOMMENDATIONS?19

A For the reasons noted herein, I find that DTE has not conclusively established that20

the proposed coal retirements are in the public interest and, consequently, there is21

1Direct Testimony of Kevin Chreston at Page 12.

2Exhibit AB-1, DTE’s response to Staff’s Data Request 2.7a.


not a clearly defined need for the Belle River CCGT in the 2022/2023 planning year. I1

recommend that the Commission deny DTE’s request for a CON and direct the2

Company to revise its retirement analysis to incorporate the significant changes in3

federal environmental and tax policy to determine if the coal retirements proposed by4

DTE are in the public interest. Similarly, DTE should also revise its IRP based CON5

analysis for the same reasons. This is particularly important as one of the requests6

made by DTE in this Docket is for cost recovery of the Proposed Project.7

In addition to directing DTE to revise its coal retirement analysis (“Coal8

Retirement Analysis”) to incorporate significant known and measurable changes in9

federal policies, I also recommend the Commission set forth a more standardized10

process for DTE to follow when performing these analyses based upon the current11

IRP filing requirements being considered by this Commission in Docket Nos. U-1841812

and U-18461. Furthermore, the Commission should ensure that if/when DTE (or13

other Michigan utilities) applies for another CON, there is a clear understanding of14

what information and models must be supplied with the filing in order to ensure the15

case can be efficiently processed.16

Q DO YOU HAVE ANY OTHER COMMENTS?17

A Yes. The fact that I do not address a particular position or assumption made by DTE18

should not be construed as agreement with that position or assumption.19


DTE’S CLAIMED ELECTRIC CAPACITY NEED1

Q WHAT IS THE BASIS OF NEED CLAIMED BY DTE THAT THE PROPOSED2

PROJECT IS EXPECTED TO FILL?3

A Due to DTE’s planned retirements of the River Rouge, St. Clair, and Trenton Channel4

Power Plants between 2020 and 2023, DTE is projecting a significant shortfall in5

capacity beginning in 2022. DTE estimates the 2022 shortfall, including a planning6

reserve margin, will be 472 MW and expects the shortfall to increase to 1,266 MW in7

2023.8

Q ARE THE COAL RETIREMENTS PLANNED BY DTE CONSISTENT WITH THE9

SERVICE LIVES FOR THE PLANTS AND THE CORRESPONDING10

DEPRECIATION RATES APPROVED BY THE COMMISSION?11

A No. The depreciation rates and expenses that are built-in to current rates are based12

on the depreciation rates and expenses that were approved in Docket No. U-16117.13

Those depreciation rates were based on the retirement dates that were proposed and14

approved in that Docket. In Case No. U-18150, DTE has applied to change its15

depreciation rates based upon a Coal Retirement Analysis that according to DTE,16

demonstrates that retirement of St. Clair, River Rouge, and Trenton Channel, is more17

economic than their continued operation.18

Q PLEASE DESCRIBE THE COAL RETIREMENT ANALYSIS PERFORMED BY DTE.19

A The Coal Retirement Analysis is an economic analysis conducted by DTE to evaluate20

the economics associated with the continued operation of its coal-fired units and the21

capital expenditures that would be required to bring the units into compliance with two22

environmental regulations. These two environmental regulations are the Steam23


Electric Effluent Limitation Guidelines (“ELG”) and the Cooling Water Intake1

Regulations (“316(b)”). This analysis was conducted by comparing the results of2

individual retirement cases to a Base Retrofit Case using the production cost model3

PROMOD under four distinct scenarios.4

The Base Retrofit Case assumed the retirement of River Rouge in 2020, St.5

Clair 1-4 and 6 in 2022, St. Clair 7 and Trenton Channel in 2023, Belle River 1 in6

2029, Belle River 2 in 2030, and Monroe post 2040. The replacement capacity in this7

scenario is a 1,500 MW CCGT in 2022 and a 1,000 MW CCGT in 2029. Because the8

retirements dates assumed in the Base Retrofit Case for Both Belle River and Monroe9

were post 2023, the Base Retrofit Case assumed compliance and the corresponding10

capital investment necessary to bring Belle River and Monroe into compliance with11

ELG and 316(b).12

DTE performed six individual retirement cases to determine if a group of units13

should be retired. St. Clair 1-4 was considered as a single group. Belle River 1 and 214

were considered as a single group. The final four groups were St. Clair 6, 7, Trenton15

Channel, and River Rouge, all considered individually. In the St. Clair, Trenton16

Channel, and River Rouge Case, the retirements were extended to 2028 and the17

plants were retrofitted with the equipment required to comply with ELG and 316(b). In18

these cases, a 1,000 MW CCGT was installed in 2022 and a 1,500 MW CCGT19

installed in 2029. The Belle River retirement case assumed retirement of the Belle20

River coal plant in 2023 with the 1,500 MW CCGT replacement installed in the same21

year. For each individual retirement case, a revenue requirement was computed and22

compared to the Base Retrofit Case. Figure 1 below illustrates how the cases were23

compared to the Base Retrofit Case.24


Figure 1

If the revenue requirement in the individual retirement cases were less than1

the Base Retrofit Case, that would mean it makes more economic sense to retrofit the2

unit and continue operation past 2023.3

DTE also performed three other sensitivities, which include High ELG Capital4

sensitivity where the ELG Capital was increased by 50%, a CO2 Price sensitivity5

where the CO2 price was increased from $0/ton to $5/ton, and a Low Market6

Capacity Price where capacity prices were modeled at $10/kW-year; all other7

assumptions remained the same.8

Q WHAT DOES DTE CLAIM ARE THE RESULTS OF THE COAL RETIREMENT9

ANALYSIS?10

A DTE claims the results of the Coal Retirement Analysis supports the retirements of St.11

Clair, Trenton Channel, and River Rouge in 2023 or earlier, and replace of that12


capacity with a CCGT, rather than spending the capital necessary to makes these1

units comply with ELG and 316(b). The retirement of these three plants is what is2

driving the need for the 1,100 MW CCGT plant which is the subject of this Docket.3

Said another way, if the St. Clair, Trenton Channel, and River Rouge coal plants were4

to operate consistent with the lives that were used when determining their current5

depreciation rates, there would be no need for the Proposed Project in the 2022/20236

planning year.7

The analysis also purports to show it is economically beneficial to retrofit both8

Belle River and Monroe to make them compliant with the federal regulations and9

allow continued operations. With the proposed retrofits, Belle River 1 would retire in10

2029, Belle River 2 would retire in 2030, and Monroe would retire in 2040.11

Q WHAT ARE THE RETIREMENT DATES THAT COINCIDE WITH DTE’S12

DEPRECIATION RATES?13

A Table 1 below shows the retirement dates that are used for the approved depreciation14

rates and the operation retirement dates used in the Coal Retirement Analysis as well15

the resultant retirement dates used in IRP modeling in this Docket and in the16

proposed depreciation rate calculations in U-18150.17


TABLE 1

Comparison of Coal Plant Lives

Plant GroupDocket No. U-16117

Retirement Dates3

RetirementDates Used inEnvironmentalRetrofit Case

Retirement DatesUsed in IRP

Modeling Based onthe Coal Retirement

Analysis

St. Clair 1-4 2019/2020 2028 2022St. Clair 6 2027 2028 2022St. Clair 7 2035 2028 2023Trenton Channel 9 2034 2028 2023River Rouge 2024 2028 2020Belle River 2050/2051 2029/2030 2029/2030

Q DOES ABATE HAVE CONCERNS REGARDING THE COAL RETIREMENT1

ANALYSIS?2

A Yes. I have a number of concerns about the validity of the Coal Retirement Analysis.3

First and foremost is the vintage of the analysis. The Coal Retirement Analysis was4

conducted in early 2016. Since that time, a new administration controls the White5

House and the federal environmental and tax policy has shifted. Similarly, the electric6

demand and commodity pricing data used in the analysis is now approaching two7

years old. Second, the approach used in the analysis is inconsistent with the method8

and risk analysis used to perform the IRP and CON replacement capacity analysis.9

Furthermore, the Coal Retirement Analysis neither used the retirement dates based10

on the currently approved depreciation rates as the baseline for comparison nor11

included increased depreciation expense in its Coal Retirement Analysis.12

3Exhibit A-14 in Case No. U-16117.


Q PLEASE EXPAND ON THIS LAST POINT REGARDING THE RETIREMENT1

DATES AND DEPRECIATION EXPENSE.2

A As shown in Table 1, above, the Coal Retirement Analysis did not consider a case3

which aligned with the current retirement dates of the units. Some of the units, such4

as St Clair 7 and Trenton Channel 9 were assumed to retire six to seven years early,5

even in the case when they were brought into environmental compliance. This would6

have impacted the economics of the analysis and increased the cost of compliance7

on an NPV basis as the capital recovery would have occurred over a shorter time8

frame.9

In addition, in Docket No. U-18150, DTE separately is requesting rates that10

would increase depreciation expense for the steam production plants, based on 201611

plant levels, by $149 million. The rates in that Docket would be applicable in DTE’s12

next general rate case. That is, in DTE’s next general rate case, it will be requesting13

approximately $149 million in additional revenues solely due to the increased14

depreciation expense it claims it will need to retire the coal plants earlier than was15

approved in Docket No. U-16117. However, in response to ABDE-4.4, DTE states16

that increased depreciation expense is not an example of increased cost to17

customers.4 DTE’s full response to ABATE Date Request 4.4 is attached to my18

testimony as Exhibit AB-2; however, the relevant portion of the response with respect19

to depreciation expense is as follows:20

Furthermore, the Company does not agree with the characterization of21“increased depreciation expenses” as an example of increased cost to22customers. The plant retirements do not result in increased revenue23requirements to customers over the long-term. Recovery of the assets24and the associated cost of removal is one of timing as it occurs via25inclusion of depreciation expense in base rates.26

27

4Exhibit AB-2, DTE’s response to ABATE’s Data Request ABDE-4.4.


Given that in Docket No. U-18150 DTE is asking for an increase of $149 million in its1

annual depreciation expense to be recovered from its customers, it is at the very2

least, disingenuous to state that this somehow is not an increased cost to customers.3

Furthermore, it is unclear whether DTE considered the change in depreciation4

revenue requirements in its economic modeling. A failure to account for this change5

would result in underestimating the cost of the Proposed Project on a NPV basis.6

Q PLEASE SUMMARIZE YOUR CONCLUSIONS REGARDING THE COAL7

RETIREMENT ANALYSIS.8

A I will discuss my concerns in detail throughout the next sections of my testimony.9

Due to these concerns, I find that DTE has not conclusively established that the10

proposed coal retirements are in the public interest and, consequently, there is not a11

clearly defined need for the Proposed Project. In particular, the Coal Retirement12

Analysis contained inputs and modeling assumptions that are no longer correct due13

to changes in environmental and tax policy by the current administration. Rather than14

ask the Commission to rule on information that is known to be incorrect, I recommend15

that the Commission deny DTE’s request for a CON and direct the Company to revise16

its retirement analysis to incorporate the significant known and measurable changes17

in federal environmental and tax policy to determine if the coal retirements proposed18

by DTE are in the public interest. In doing so, DTE should also update its load19

forecast, commodity inputs and other time sensitive data to reflect the most current20

information. Finally, DTE should be required to perform the base case analysis and21

risk assessment sensitivities consistently with the method and risk analysis it will22

perform when assessing replacement capacity if the results of its updated Coal23

Retirement Analysis demonstrate a need for additional capacity.24


CHANGES IN FEDERAL POLICIES1

Q PLEASE SUMMARIZE THE FEDERAL POLICIES THAT HAVE CHANGED OR2

BECOME MORE UNCERTAIN SINCE DTE BEGAN ITS COAL RETIREMENT, IRP3

AND CON ANALYSIS.4

A First, On December 22, 2017, President Donald Trump signed into law the Tax Cuts5

and Jobs Act of 2017 (“TCJA”) which contains provisions reducing the corporate tax6

rate and revising the federal tax structure. These new federal requirements affect the7

current tax expense and deferred tax accounting methods used by corporations,8

including utilities. Most of the provisions of the TCJA go into effect on9

January 1, 2018. This Commission has recognized the magnitude of this change in10

policy and the potential for it to reduce costs to Michigan ratepayers. Consequently,11

the Commission recently ordered all Michigan utilities to apply regulatory accounting12

treatment, including regulatory assets and liabilities, for all impacts resulting from the13

TCJA.514

Second, the economic analysis DTE performed and relied upon to assess the15

future of its coal-fired generation was performed in the spring of 2016 and16

incorporates assumptions related to the Clean Power Plan (“CPP”) even though this17

regulation has been stayed by the U.S. Supreme Court.18

A similar circumstance is occurring with the ELG. The current administration19

has indicated its intent to review and potentially revise the ELG requirements and20

compliance dates. The EPA has postponed certain compliance dates from21

2018-2023 to 2020-2023.22

5Docket No. U-18494, Order, dated 2017-12-27.


Q WAS DTE AWARE OF THE CHANGES IN FEDERAL ENVIRONMENTAL1

POLICIES WHEN IT PERFORMED ITS COAL RETIREMENT ANALYSIS?2

A DTE was aware that the CPP had been stayed and that litigation was remanded back3

to the Circuit Court for review when it conducted its Coal Retirement Analysis. Since4

that time, additional uncertainties were added due to the outcome of the 2016 U.S.5

Presidential election and corresponding change in direction undertaken by the new6

Trump administration. In particular, the new President recently issued an Executive7

Order titled “Promoting Energy Independence and Economic Growth” that instructed8

the EPA to review the CPP and suspend, revise or rescind the rule if appropriate.69

In addition to the CPP, the EPA also recently announced a stay of the ELG10

regulations for reconsideration.7 Prior to the stay, DTE estimated that it would take11

$370 million to bring its entire coal fleet into compliance with ELG; however, the12

outcome of the reconsideration and any potential changes in the regulations may13

greatly impact the investment necessary for operation of the existing facilities.14

Q HOW DO THESE POLICIES AFFECT THE ANALYSIS PERFORMED BY DTE?15

A The environmental policies and the associated capital costs required to comply with16

the regulations are the driving factor behind DTE’s proposal to retire the coal assets17

that then create the need for the Proposed Project. It is possible that some of these18

regulations may be delayed further or removed all together. However, even if the19

regulations remain, due to the way a utility’s revenue requirement is set, the change20

the federal corporate tax rate necessarily changes the costs to comply with the21

environmental regulations and, consequently, renders DTE’s analysis incorrect22

regardless of the ultimate environmental compliance deadlines.23

6Direct Testimony of Barry Marietta at page 14.

7Id.


Q PLEASE EXPLAIN HOW THE CPP IMPACTED THE COAL RETIREMENT1

ANALYSIS.2

A The CPP was a proposed environmental regulation that would have severely limited3

the allowed CO2 emissions from power plants after 2030. It is apparent that for coal4

plants that were expected to retire after 2030, DTE arbitrarily moved the retirement5

dates to 2030 or before without any analysis performed on the reasonableness of that6

decision. The lack of any supporting analysis or reasoning for the adjustment to 20307

or before makes the choice appear arbitrary, since the dates could have equally been8

2027 or before, or 2032 or before. Prior to this analysis being performed and the9

announcement of the CPP, Belle River 1 and 2 were expected to retire in 2050 and10

2051, St. Clair 7 was expected to retire in 2035 and Trenton Channel 9 was expected11

to retire in 2034. DTE has produced no studies or justification of moving from these12

retirement dates to those utilized in the Base Retrofit Case, which assumed 2029 and13

2030 for Belle River 1 and 2, and 2028 for St. Clair 7 and Trenton Channel 9.14

Q PLEASE EXPLAIN HOW ELG IMPACTED THE COAL RETIREMENT ANALYSIS.15

A Compliance with ELG and 316(b) are the predominant factors driving the retirements16

resulting from the Coal Retirement Analysis that create the capacity shortfall and17

corresponding need for new capacity in the 2022/2023 planning year. Between the18

316(b) and ELG regulations, DTE expects compliance with ELG to be more costly.819

The ELG regulations will impact DTE’s coal-fired units. Compliance would require20

significant modifications at all existing power plants. Under the current ELG21

regulations, the required process and equipment modifications would necessitate22

extensive capital projects for any unit that would remain in service beyond the23

8Direct Testimony of Kevin Chreston at page 25.


compliance deadline. DTE estimates that capital expenditures to comply with ELG1

are estimated at $370 million for all of DTE’s existing coal plants; however, since2

performing the analysis, the EPA announced a stay of the ELG regulations for3

reconsideration. The outcome of the reconsideration and any potential changes4

in the regulations may greatly impact the total investment and timing necessary5

for continued operation of existing facilities.96

In response to a Staff Data Request, DTE acknowledged that the economics7

for River Rouge, St. Clair and Trenton Channel would be improved if ELG continues8

to be stayed. DTE has not performed the full economic analysis to determine9

whether the continued stay of ELG alone would change the outcome of the analysis10

for any of the plants. However, DTE also indicated that economics were not the only11

consideration for the decision to retire. In addition, DTE also considered the12

increased risk of failures, higher costs to operate and maintain the units, potential13

future regulations, as well as DTE’s recently announced low carbon aspiration.1014

Q DO YOU AGREE WITH DTE’S RESPONSE TO THE STAFF?15

A No. In fact, I think that a properly updated analysis would address not only the16

question regarding the economics of a continued stay regarding ELG, but also the17

other considerations listed by DTE. It is obvious that performing an updated18

economic analysis with the most current information available regarding DTE’s load19

forecast, commodities and incorporating modeling assumptions that reflect the20

potential for a continued stay would answer the economic questions around that21

issue. Furthermore, DTE could address its concerns regarding increases in O&M22

costs or decreases in unit availability as these could be modeled and quantified. If23

9Direct Testimony of Barry Marietta at page 6.

10Exhibit AB-3, DTE’s response to Staff’s Data Request 2.7b.


DTE has not incorporated these assumptions into its exiting analysis, then this is yet1

another reason why the analysis cannot be relied upon.2

With respect to the future potential environmental regulations, this type of risk3

is fully considered, or should be fully considered by an IRP/CON resource planning4

analysis. As I will discuss later, ensuring that the Coal Retirement Analysis is5

performed consistently with the rest of the analyses, including a full set of scenarios6

and sensitivities, would provide the Commission the necessary information to assess7

whatever potential future environmental regulations the Company chose to model in8

its set of risk scenarios.9

Finally, DTE’s low carbon aspiration should be considered within the confines10

of the Michigan RPS and DTE’s obligation to provide reliable electric service at lowest11

reasonable cost. Ratepayers should not be forced to pay higher costs due to internal12

DTE policies. If DTE can conclusively demonstrate its proposal aligns with its13

obligation to provide reliable electric service at lowest reasonable cost, then the14

Commission should seriously consider that alternative. Once again, the solution is to15

update the analysis and provide those results to the Commission so it can make an16

informed decision with the best information possible.17

Q HOW WOULD THE REFORMS CONTAINED WITHIN THE TAX CUTS AND JOBS18

ACT SIGNED INTO LAW ON DECEMBER 22, 2017 IMPACT THE ANALYSIS?19

A The full effects of this law are unclear as much depends on how DTE intends to20

approach excess deferred income taxes and other tax nuances. ABATE submitted21

discovery to DTE regarding the TCJA and its effects but did not have the responses22

prior to the filing of this testimony.23


With that being said, the change in the federal corporate tax rate alone should1

be enough cause for the analyses to be revised. Any capital projects that are2

financed by DTE with equity resources are grossed up for taxes when determining3

the effective revenue requirement. The reduction in the federal corporate tax rate4

would then lower the revenue requirements of incremental capital expenditures paid5

for by customers. As a consequence, the revenue requirements considered in the6

Coal Retirement Analysis, as well as the resource planning analysis supporting the7

Proposed Project, are now incorrect and overstated. In addition to the direct effects8

of the change in the corporate tax rate there are also revenue requirement effects9

associated with the flow back of excess accumulated deferred income taxes. The10

Commission should understand these revenue requirement implications, prior to11

making a decision in this Docket, including how they will affect the Coal Retirement12

Analysis and the Proposed Project.13

As I mentioned earlier, this Commission has recognized the magnitude of this14

change in tax policy and the potential for it to reduce costs to Michigan ratepayers.15

Consequently, the Commission recently ordered all Michigan utilities to apply16

regulatory accounting treatment, inclusive of regulatory assets and liabilities, for all17

impacts resulting from the TCJA.11 The Commission should be equally concerned18

with understanding the effect in the instant Docket because it has the potential for a19

billion dollar impact to customers.20

11Docket No. U-18494, Order, dated 2017-12-27.


Q WOULD IT BE IN THE PUBLIC INTEREST TO MOVE FORWARD IN THIS1

DOCKET WITHOUT UPDATING THE ANALYSIS FOR THESE KNOWN AND2

MEASURABLE CHANGES?3

A No. While it is certainly possible that the outcome of a revised analysis will be the4

same, the fact of the matter is that the current analysis put forth by DTE is now known5

to be factually and materially incorrect due to the TCJA. Consequently, the6

Commission cannot maintain the public interest and simultaneously knowingly rely7

upon incorrect information. At the same time, it would be fundamentally unfair to8

allow DTE to revise its analysis and then offer this new analysis in its rebuttal9

testimony, without allowing other parties to this Docket to conduct full discovery and10

then offer testimony responding to the new analysis. For these reasons, I11

recommend the Commission deny DTE’s requested CON. Alternatively, I12

recommend that the Commission vacate the current schedule, require DTE to13

address each of these issues in its rebuttal testimony and allow the Staff and14

Intervenors the opportunity to conduct discovery and file responsive testimony to the15

new analysis. This is particularly important as one of the requests made by DTE in16

this Docket is for cost recovery of the Proposed Project.17

Q PLEASE EXPAND ON YOUR LAST STATEMENT.18

A In this filing, DTE is seeking three CONs. The first and second CONs deal with the19

need for the project and the reasonableness/prudency of the project in relation to the20

defined need. The third CON requests the estimated costs be recoverable in rates.21

In my opinion, the preapproval of costs necessitates that the Commission apply very22

strict scrutiny when examining the reasonableness of the Proposed Project. I would23


recommend against preapproving any costs for recovery based upon an analysis that1

is known to be incorrect, which is a fact in this Docket due to the TCJA.2

Q ARE OTHER COMMISSIONS REQUIRING UTILITIES TO UPDATE OPEN3

DOCKETS TO UNDERSTAND THE EFFECTS OF THE TCJA RATHER THAN4

MAKING A DECISION BASED ON INCORRECT INFORMATION?5

A Yes. Many Commissions are concerned with this issue and are taking action in6

different ways. One example involves a utility that operates in both Michigan and7

Indiana, Indiana Michigan Power Company (“I&M”). The Indiana Utility Regulatory8

Commission (“IURC”) issued a Docket Entry in Cause No. 44967 on January 3, 20189

requiring I&M to update any schedules that are impacted by the TCJA by10

January 10, 2018. I have attached a copy of this Docket Entry as Exhibit AB-4. In11

addition to I&M, the IURC also approved a schedule change in the Northern Indiana12

Public Service Company (“NIPSCO”) case based on all parties’ agreement to update13

for TCJA.12 Of particular note in this motion is Paragraph 7 to which the utility,14

NIPSCO, is a signatory. Paragraph 7 states:15

Insofar as the changes in federal tax law have a material bearing on16the merits of the rate proposals put forward by NIPSCO, the burden of17moving forward with evidence in this regard properly falls on NIPSCO.18NIPSCO prepared and submitted its case-in-chief evidence premised19on tax assumptions that are no longer accurate. That case-in-chief20evidence is deficient in light of the changed circumstances as to21federal taxes. Joint Movants do not suggest there was any fault on the22part of NIPSCO in failing to anticipate and address the changes in23federal tax law that occurred three months after the initial submission24occurred in this case.25

Indeed the statements contained within this motion are true of all utilities with active26

filings that contain analyses containing calculations that rely, in part, on the corporate27

tax rate. Similar to what is stated in the motion, I do not suggest that DTE is at fault28

12Exhibit AB-5, Joint Motion Revise the Procedural Schedule to Allow for the Submission of

Evidence Regarding Material Changes in Federal Law. Cause No. 44988.


for failing to address the changes in federal tax law that occurred almost six months1

after DTE’s initial submission occurred in this Docket. However, the incontrovertible2

fact is that the submission originally made by DTE is now deficient in light of the3

changes to federal taxes.4

Another example, while not contained within a Commission order, but5

addressed by parties to a CON case in New Mexico via settlement agreement, is an6

agreement by the utility to provide a fully update economic analysis if the federal7

corporate tax rate changed. The hearing examiner asked many witnesses regarding8

this issue during the public hearings which occurred on December 18-20, 2017.139

Other examples involve issuing orders that incorporate provisions for updates or10

special regulatory treatments to address changes in the tax law.14 Finally, some11

commissions, including this one, have issued orders asking for dockets to be opened12

to examine the effects on regulated utilities rates.1513

Q WHAT ARE YOUR CONCLUSIONS REGARDING THE CHANGE IN FEDERAL14

ENVIRONMENTAL AND TAX POLICIES?15

A Given the known changes resulting from the recently enacted TCJA, as well as the16

changes in the environmental policy related to the CPP and ELG, I recommend that17

either the Commission deny DTE’s application or require DTE to update its Coal18

Retirement and CON analyses to incorporate the known and measurable changes19

and fully examine the risks and uncertainties created by the changes in federal20

policies. As I will discuss in the next section of this testimony, I further recommend21

the Commission require that regardless of whether the Commission denies the22

application or requires an update, these two analyses must both reflect the most23

13New Mexico PRC Case No. 17-00044-UT.

14New Mexico PRC Docket No. 16-00276-UT & Nevada PUC Docket No. 17-06003.

15Also Utah, Missouri, Idaho, North Carolina, and likely many others.


recent load forecast and commodity information available, as well as any other time1

sensitive cost (or other) information and be performed using a consistent analytical2

method and consistent set of risk scenarios.3

CONSISTENCY IN CON FILING POLICIES4

Q PLEASE DESCRIBE THE INCONSISTENCY BETWEEN THE COAL RETIREMENT5

ANALYSIS AND THE IRP AND CON ANALYSES.6

A The basis of DTE’s IRP and CON filing is a Strategist® analysis to select the most7

cost effective resource under a given set of scenarios and sensitivity assumptions to8

meet capacity and energy obligations. Indeed, this type of analysis is performed by9

many utilities when assessing the economics of resource planning. Some utilities,10

DTE included, will then further refine the Strategist-based analysis by developing11

more detailed revenue requirement models for the resources selected by Strategist.12

Typically, a subset of scenarios and sensitivity assumptions believed to be the most13

influential will then be evaluated through the use of more rigorous variable cost14

models like PROMOD. The results of these computations are then used in15

conjunction with spreadsheets and other tools used to more explicitly represent the16

fixed revenue requirements and regulatory accounting unique to the utility performing17

the analysis.18

However, when performing the Coal Retirement Analysis, DTE neither19

performed a Strategist® analysis nor considered the same set of scenarios and20

sensitivity assumptions utilized in the CON and IRP analyses. The Coal Retirement21

Analysis and the CON analysis did not even use the same set of base inputs such as22

load forecasts and commodity prices. Given the dependence between the Coal23

Retirement Analysis and the need that the requested CON is based upon, using24


consistent and timely assumptions is paramount. With consistency between the Coal1

Retirement Analysis and the CON analysis, DTE has yet to complete the analyses,2

scenarios, and sensitivities necessary to support its $1 billion ask of ratepayers in this3

proceeding.4

Q IS THE CIRCUMSTANCE OF POTENTIAL ENVIRONMENTAL COAL5

RETIREMENTS AND THE CORRESPONDING NEED FOR REPLACEMENT6

CAPACITY UNIQUE TO DTE OR MICHIGAN?7

A No, though there are some nuances unique to Michigan. As environmental8

regulations have become more stringent in recent years, along with a significant9

decline in the cost for natural gas and increases in renewable energy standards, the10

U.S. has seen tens of thousands of megawatts of aging coal-fired capacity retired and11

it is unlikely that new coal plants will be built going forward. Indeed, this is12

exemplified by historically coal-centric utilities such as American Electric Power and13

PacifiCorp transitioning away from coal resources to natural gas-fired and renewable14

generation technologies. This fact, coupled with the increasing age of the U.S. coal15

generation fleet, foreshadows a nationwide trend for which Michigan is no exception.16

One distinction for Michigan, that is not shared by the U.S. as a whole, is the17

particular geography situation with respect to transmission limitations created by the18

current transmission system to Michigan’s lower peninsula because of the situation of19

the Great Lakes on its borders. The effects of these limitations will necessitate that20

more replacement capacity will be built within Michigan near its loads, relative to other21

regions in the U.S. As a consequence, it is likely that Michigan will see more CON22

filings from its regulated utilities in the coming years. However, this does not mean23

that the Commission should jump to any conclusions in this case, especially24


considering that the economic analysis filed by DTE is incomplete and incorrect. The1

current White House administration’s shift in federal policies potentially offers a “stay2

of execution” for the plants at risk for immediate retirement. The additional time3

created by the shift in federal policies provides a chance for the Commission to4

require DTE to go back and revise its analysis to provide the Commission a complete5

and consistent analysis upon which to base a decision.6

Q IS THERE A DEADLINE TIME BY WHICH DTE MUST MAKE A DECISION OR7

COULD DELAYING THIS DECISION LEAD TO RELIABILITY PROBLEMS IN THE8

FUTURE?9

A In discovery, ABATE asked DTE about the timing to comply with the regulations and10

when it must make a decision. DTE responded that currently there is not a specific11

date when a decision to retire the coal plants must be made to comply with ELG and12

316(b).16 However, DTE went on to say, that given the age of the plants and the13

costs to comply with the regulations, DTE concluded, at this point in time, the most14

reasonable and prudent decision is to retire the plants.17 However, as I have15

discussed, this conclusion is based upon incorrect, inconsistent, and outdated16

information.17

Furthermore, it is exactly this decision to retire the coal plants that create the18

reliability concerns and need for new resources. Currently, these plants exist and19

provide capacity to customers. DTE’s proposal allows DTE to create a reliability20

problem of its own doing. The Commission should not allow DTE to create a21

reliability problem where one does not exist. Further, the Commission should not22

16Exhibit AB-6, DTE’s response to ABATE’s Data Request ABDE 2.7.

17Id.


approve retirement of these assets without first deciding, based on the best available1

information at the time, retiring the plants is in the public interest.2

Q GIVEN THE LIKELIHOOD OF ADDITIONAL CON FILINGS IN THE COMING3

YEARS, WHAT CAN BE DONE TO IMPROVE THE PROCESS?4

A There are a number of lessons that can be learned from this Docket as well as5

synchronization between the CON filings and the IRP filing requirements along with6

the associated IRP Strawman proposal under consideration by this Commission in7

Docket Nos. U-18418 and U-18461. In fact, in its Opinion and Order in Docket No.8

U-18461, the Commission recognized that the risk assessment scenarios should be9

consistent between a CON filing and an IRP filing.18 I would further this idea to fully10

encompass not just the CON filing and analysis used to select a new resource, but11

also in the context of an economic retirement analysis (or similarly, an analysis to12

determine the economics behind a Power Purchase Agreement such as the one13

considered for amendment recently by the Commission in Consumers Energy14

Company Docket No. U-18250).15

Q WHAT OTHER LESSONS CAN BE LEARNED FROM THIS PROCEEDING?16

A In addition to ensuring consistency going forward within all of the analyses relied17

upon to support the filing, there are other issues as well that the Commission should18

consider. At the top of the list is the amount of data and the overall size of the filing19

that must be reviewed. This filing was massive. DTE witness Chreston alone had20

almost 500 workpapers and relied upon multiple models/software. In order to21

facilitate an efficient process, I recommend that a technical conference for experts be22

18Opinion and Order, Docket No. U-18461, dated 2017-12-20 at page 7.


scheduled to understand the workflow, location of data, development of model inputs,1

and other technical considerations. This technical conference proposal is not2

suggested as a forum to argue over methods, but a forum to understand the data and3

processes used by the utility in its IRP and CON analyses to evaluate and prepare a4

CON application.5

Along a similar line, I would also note that this is the second CON filing where6

the ALJ ordered that the Applicant make certain modeling software available to7

intervenors (Strategist® and PROMOD). If proprietary software and modeling results8

access barriers are going to become a regular part of the CON process, the9

Commission should make that known and ensure that there is a reasonable time and10

process to obtain the software to ensure maximum value to the regulatory process.11

Q REFERENCING YOUR STATEMENT REGARDING THE MODELS, CAN YOU12

DISCUSS WHY ABATE DID NOT PRESENT MODELING RESULTS EVEN13

THOUGH IT HAD ACCESS TO THE MODELS?14

A Yes. There are two primary reasons. As I have discussed at length in this testimony,15

the inputs and analysis used by the Company are outdated and inconsistent with16

current federal policies. Had ABATE used DTE’s models as the starting point for any17

analysis, ABATE would be supporting the use of incorrect information to form18

conclusions regarding the reasonableness of DTE’s request for a CON.19

The second reason is the consistency of methods used between the Coal20

Retirement Analysis and the resource planning analysis used to support the21

Proposed Project. One of ABATE’s strongest concerns is the Coal Retirement22

Analysis, and specifically, the lack of a Strategist® based analysis as the starting23

point for the Coal Retirement Analysis. Strategist® can be used to assess the24


economics of retirement versus retrofit alternatives simultaneously with replacement1

capacity options. But DTE failed to do that in this case. As I discussed earlier, this2

should have been modeled by DTE with assumptions reflecting that those plants that3

are retrofitted and are currently expected to remain in service beyond 2028, are4

modeled to remain in service through their expected useful lives). In other5

jurisdictions, I have reviewed retirement analyses performed using Strategist® in6

which the replacement alternatives were considered simultaneously, or co-optimized,7

with the potential retirement alternatives. This makes perfect sense because these8

decisions are mutually dependent. Indeed, this was one of the types of analysis9

considered by ABATE; however, because there was no Strategist® case built to10

consider the retirements as alternatives, it would have been nearly impossible to11

convert the existing Coal Retirement Analysis into a Strategist® model, ensure data12

integrity and prepare testimony within the time frame ABATE had access to the13

model.14

Q WHAT DO YOU CONCLUDE REGARDING THE CONSISTENCY OF THE15

ANALYSES RELIED UPON IN THIS FILING?16

A There are a number of inconsistencies contained within the analyses DTE conducted17

and relied upon in support of its request for a CON. In order to assure that the public18

interest is preserved, consistency must be maintained across the inputs, and in the19

instance of similar problems, similar methods and models should be employed. This20

starts with having a well understood process and ensuring a relevant, status quo case21

for a baseline from which to compare each alternative.22


Q WHAT DO YOU RECOMMEND WITH RESPECT TO THE CONSISTENCY1

ISSUES?2

A My recommendation with respect to these issues is in accord with my3

recommendations throughout this testimony; the Commission should deny DTE’s4

request for a CON in this Docket. Alternatively, the Commission should direct DTE to5

revise its coal retirement and replacement capacity analyses used to support this6

filing to reflect a consistent set of updated inputs and assumptions, as well as a7

consistent set of alternative scenarios and sensitivities to assess the risks faced by8

this decision.9

In doing so, I recommend the Commission require that any updated analysis10

filed in this Docket or analyses supporting future CON filings maintain consistency11

internally and, where possible, align with or stem from the recent IRP filing12

requirements and Strawman proposals considered by this Commission. Furthermore,13

I recommend the Commission consider the lessons learned from this Docket and14

ensure that in the future the process is clear with respect to the models/software,15

sharing of data, setting of technical conferences, etc. to ensure the CON process is16

efficient and in the best interest of the ratepayers.17

Q PEASE SUMMARIZE YOUR CONCLUSIONS AND RECOMMENDATIONS.18

A For the reasons noted herein, I find that DTE has not conclusively established that19

the proposed coal retirements are in the public interest and, consequently, there is20

not a clearly defined need for the Belle River CCGT in the 2022/2023 planning year. I21

recommend that the Commission deny DTE’s request for a CON, or in the alternative,22

direct the Company to revise its retirement analysis to incorporate the significant23

changes in federal environmental and tax policy to determine if the coal retirements24


proposed by DTE are in the public interest. Similarly, DTE should also revise its IRP1

based CON analysis for the same reasons. This is particularly important as one of2

the requests made by DTE in this Docket is for cost recovery of the Proposed Project.3

In addition to directing DTE to revise its Coal Retirement Analysis, I also4

recommend the Commission set forth a more standardized process for DTE to follow5

when performing these analyses based upon the current IRP filing requirements6

being considered by this Commission in Docket Nos. U-18418 and U-18461.7

Furthermore, the Commission should ensure that if/when DTE (or other Michigan8

utilities) applies for another CON, there is a clear understanding of what information9

and models must be supplied with the filing in order to ensure the case can be10

efficiently processed.11

Q DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?12

A Yes, it does.13

Appendix ANicholas L. Phillips

Page 1

BRUBAKER & ASSOCIATES, INC.

Qualifications of Nicholas L. Phillips

Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.1

A Nicholas L. Phillips. My business address is 16690 Swingley Ridge Road, Suite 140,2

Chesterfield, MO 63017.3

Q PLEASE STATE YOUR OCCUPATION.4

A I am a consultant in the field of public utility regulation and an Associate with the firm5

of Brubaker & Associates, Inc. (“BAI”), energy, economic and regulatory consultants.6

Q PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND PROFESSIONAL7

EMPLOYMENT EXPERIENCE.8

A I graduated from the Washington University in St. Louis/University of Missouri-St.9

Louis joint engineering program in 2010 where I received a Bachelor of Science10

degree in Electrical Engineering. In 2012 I received the degree of Master of11

Engineering in Electrical Engineering with a concentration in Electric Power and12

Energy Systems from Iowa State University of Science and Technology. In 2015 I13

received a Master of Science Degree in Computational Finance and Risk14

Management from the University of Washington Seattle. I am a member of the Power15

and Energy Society of the Institute of Electrical and Electronics Engineers.16

I joined BAI as an intern in 2009 and upon graduation, I accepted a position17

with BAI as an Associate Engineer. In January of 2012, I was promoted to the18

position of Associate Consultant, in January of 2013 I was promoted to the position of19

Consultant at BAI, in January of 2014 I was promoted to my the position of Senior20

Consultant at BAI, and in January of 2016 I was promoted to my current position of21

Associate at BAI. While at BAI, I have been involved with numerous regulated and22

Appendix ANicholas L. Phillips

Page 2

BRUBAKER & ASSOCIATES, INC.

competitive electric service issues. These have included transmission planning,1

resource planning, electric price forecasting, load forecasting, cost of service,2

combined heat and power steam costs and power procurement. This has involved3

the performance of power flow, production cost, transmission line routing, cost of4

service and other analysis to address these issues.5

Prior to joining BAI, through the department of Electrical and Computer6

Engineering and the Medical School at Washington University in St. Louis, I aided in7

preliminary research focusing on the use of ultrasound as a mechanism for in vitro8

localized thermometry.9

BAI and its predecessor firm have participated in more than 700 regulatory10

proceedings in 40 states and Canada.11

BAI provides consulting services in the economic, technical, accounting, and12

financial aspects of public utility rates and in the acquisition of utility and energy13

services through RFPs and negotiations, in both regulated and unregulated markets.14

Our clients include large industrial and institutional customers, some utilities and, on15

occasion, state regulatory agencies. We also prepare special studies and reports,16

forecasts, surveys and siting studies, and present seminars on utility-related issues.17

In general, we are engaged in energy and regulatory consulting, economic18

analysis and contract negotiation. In addition to our main office in St. Louis, the firm19

also has branch offices in Phoenix, Arizona and Corpus Christi, Texas.20

\\Doc\Shares\ProlawDocs\MED\10481\334525.docx

MPSC Case No.: U-18419

Respondent: K. J. Chreston/B.J. Marietta

Requestor: STAFF

Question No.: STDE-2.7a

Page: 1 of 1

Question: Please reference page 23 of Mr. Chreston’s testimony.

a. The Company mentions ELG and 316(b) regulations, were other

emerging environmental regulations assumed in the company’s analysis resulting in the River Rouge, St. Clair and Trenton Channel facilities being uneconomical?

Answer: The Retirement Analysis was run in spring of 2016, and other environmental

regulations were considered. The National Ambient Air Quality Standards (NAAQS) were considered. The Cross-State Air Pollution Rule (CSAPR) with stricter NOX and SO2 budgets was also considered along with forecasted ozone season reductions beginning in May 2017. The underlying environmental basis in the analysis assumed the Clean Power Plan to be in effect, even though it had been stayed by the US Supreme Court at the time of the study. It was assumed that the court action would keep the CO2 regulations uncertain for some time. To account for some of the CO2 uncertainty, a CO2 price sensitivity was run.

Case No.: U-18419 Exhibit: AB-1

Witness: Nicholas L. Phillips Date: January 12, 2018

Page 1 of 1

MPSC Case No.: U-18419 Respondent: I. M. Dimitry/T.M. Uzenski Requestor: ABATE Question No.: ABDE-4.4 Page: 1 of 2 Question: Please explain if the Company has performed any analysis that captures

the increased cost to customers associated with the early retirement of the coal plants. An example of increased costs is the estimated $149.6 million in additional steam production depreciation expense that DTE has proposed in Docket No. U-18150. If this type of analysis has been performed, please provide in its complete format, with all formulas and links intact, as well as all supporting workpapers. If this analysis has not been performed, please provide a detailed narrative explaining why such an analysis has not been performed.

Answer: It is unclear what is meant by “the early retirement of the coal plants.” The

Company does not consider the planned retirement dates for the Tier 2 plants as discussed in this case to be “early.” As part of its long-term resource planning, the Company has determined that a number of coal plants will be retired between now and 2023 due to age, environmental requirements, and the Company’s commitment toward building a cleaner, sustainable generation fleet.

Furthermore, the Company does not agree with the characterization of “increased depreciation expenses” as an example of increased cost to customers. The plant retirements do not result in increased revenue requirements to customers over the long-term. Recovery of the assets and the associated cost of removal is one of timing as it occurs via inclusion of depreciation expense in base rates. The Company uses the Group Method of depreciation and generally does not track depreciation reserves within each utility account down to the individual plant level. (An exception is the Belle River plant, where the Company is required to separately account for depreciation.) At the time an individual plant retires, any undepreciated plant balances will be recovered through the process of redistributing reserve balances and resetting depreciation rates for the remaining plants in the group. An economic analysis was conducted that led to a conclusion that retirement of River Rouge 3, St. Clair Units 1 – 4, St. Clair Unit 7, and Trenton Channel Unit 9 was favorable for customers compared to the capital investment and expenses required to safely operate and maintain these units with the revised environmental regulations. The resource planning process and the economic analysis associated with the planned retirements of the Tier 2 coal plants is described the testimony of witnesses



Page 1 of 2

MPSC Case No.: U-18419 Respondent: I. M. Dimitry/T.M. Uzenski Requestor: ABATE Question No.: ABDE-4.4 Page: 2 of 2

Dimitry and Chreston and described in the Planned Retirements section of the IRP Report (Exhibit A-4 2nd Revised, Section 6.3). In addition, see response to ABDE-2.12.



Page 2 of 2

MPSC Case No.: U-18419

Respondent: K. J. Chreston

Requestor: STAFF

Question No.: STDE-2.7b

Page: 1 of 1

Question: Please reference page 23 of Mr. Chreston’s testimony.

b. If ELG continues to be stayed, but 316(b) moves forward, how would

that affect the Company’s economic analysis of the above-mentioned facilities?

Answer: The economic analysis of St. Clair, Trenton and River Rouge would be

impacted, improving the economics due to the elimination of the potential ELG investments. However, based on the simplified math of summing the delta NPV (i.e. the difference in NPV of making the ELG investments necessary for continued operation vs. the NPV of retiring the units) results and the ELG compliance capital of each grouping of units, the delta NPVs would still be negative. Additionally, economics are not the only factor considered in determining whether a unit should be retired. Other considerations include the associated higher cost to operate and maintain the units along with increased risk of failures, and the potential future environmental regulations as well as DTE Electric’s recently announced low carbon aspiration.



Page 1 of 1

FILED

STATE o/ INDIANA

JAN 03 2010

REGu~rv: UTILITY GQAfMISSQv

INDLI\NA UTILITY REGUL.\TORY CO!vllv!ISSION 101 WEST WASHINGTON STREET, SUITE 1500 EAST

INDIA.T\IAPOUS, INDLI\NA 46204-3419

>'•"n•;.in.gov/iurc

Office: (317) 232-2701

Facsimile: (317) 232-6758

PETITION OF INDIANA MICIDGAN POWER COMPANY, ) AN INDIANA CORPORATION, FOR (1) AUTHORITY TO ) INCREASE ITS RATES AND CHARGES FOR ELECTRIC ) UTILITY SERVICE THROUGH A PHASE IN RATE ) ADJUSTMENT; (2) APPROVAL OF: REVISED ) DEPRECIATION RATES; ACCOUNTING RELIEF; ) INCLUSION IN BASIC RATES AND CHARGES OF ) QUALIFIED POLLUTION CONTROL PROPERTY, CLEAN ) CAUSE NO. 44967 ENERGY PROJECTS AND COST OF BRINGING I&M'S ) SYSTEM TO ITS PRESENT STATE OF EFFICIENCY; RATE ) ADJUSTMENT MECHANISM PROPOSALS; COST ) DEFERRALS; MAJOR STORM DAMAGE RESTORATION ) RESERVE AND DISTRIBUTION VEGETATION ) MANAGEMENT PROGRAM RESERVE; AND ) AMORTIZATIONS; AND (3) FOR APPROVAL OF NEW ) SCHEDULES OF RATES, RULES AND REGULATIONS. )

You are hereby notified that on this date the Indiana Utility Regulatory Commission ("Commission") has caused the following entry to be made:

On December 22, 2017, President Donald Trump signed into law the Tax Cuts and Jobs Act of 2017 ("Act''). 1 The Act contains provisions reducing the corporate tax rate of 35% to 21% and revising the federal tax structure. These new federal requirements affect the cunent tax expense and deferred tax accounting methods used by employers, including utilities. Many of the Act's provisions go into effect on January 1, 2018. Thus, Petitioner shall update any schedules submitted in this proceeding that are impacted by the Act by January 10, 2018.

IT IS SO ORDERED.

1 Pub. L. No. 115-97, 131 Stat 2054 (2017).



Page 1 of 2

David E. V eleta, Senior Administrative Law Judge

Date: _ ____..:./_-_:S-----' .. J'---2( ______ _



Page 2 of 2

STATE OF INDIANA

INDIANA UTILITY REGULATORY COMMISSION

PETITION OF NORTHERN INDIANA PUBLICSERVICE COMPANY FOR (1) AUTHORITYTO MODIFY ITS RATES AND CHARGES FORGAS UTILITY SERVICE THROUGH A PHASEIN OF RATES; (2) MODIFICATION OF THESETTLEMENT AGREEMENTS APPROVED INCAUSE NO. 43894; (3) APPROVAL OF NEWSCHEDULES OF RATES AND CHARGES,GENERAL RULES AND REGULATIONS,AND RIDERS; (4) APPROVAL OF REVISEDDEPRECIATION RATES APPLICABLE TO ITSGAS PLANT IN SERVICE; (5) APPROVAL OFNECESSARY AND APPROPRIATEACCOUNTING RELIEF; AND (6)AUTHORITY TO IMPLEMENT TEMPORARYRATES CONSISTENT WITH THEPROVISIONS OF IND. CODE CH. 8-1-2-42.7

)))))))))))))))))

CAUSE NO. 44988

JOINT MOTION TO REVISE THE PROCEDURAL SCHEDULE

TO ALLOW FOR THE SUBMISSION OF EVIDENCE REGARDING MATERIAL CHANGES IN FEDERAL TAX LAW

All parties, including Northern Indiana Public Service Company (“NIPSCO”), the

Indiana Office of Utility Consumer Counselor (“OUCC”), NIPSCO Industrial Group (“IG”),

Citizens Action Coalition (“CAC”), Direct Energy Business Marketing, LLC and Direct Energy

Services, LLC (“Direct Energy”), NIPSCO Gas Supplier Group (“GSG”), and Steel Dynamics,

Inc. (“SDI”) (collectively “Joint Movants”), by counsel, submit this motion to revise the

procedural schedule in this proceeding, in order to establish a reasonable process for the

submission of evidence concerning the changes in federal tax law effective January 1, 2018.

Those changes, which include a reduction in the federal corporate income tax rate from 35% to

21%, have a substantial impact on the rate relief sought by NIPSCO. The existing procedural

schedule did not contemplate that material change and accordingly, requires revision in order to



Page 1 of 7

VLucas

Filings Stamp

2

permit the development of an evidentiary record on the substantial reduction in NIPSCO’s

federal tax liability and the corresponding impact on the determination of just and reasonable

rates. In support of this motion, Joint Movants state as follows:

1. NIPSCO commenced this proceeding on September 27, 2017, with the filing of its

Petition along with its case-in-chief evidence, consisting of the written testimony and exhibits of

fourteen witnesses. NIPSCO utilized a forward-looking test year ending December 31, 2018.

All of its case-in-chief evidence, supporting schedules, and rate computations reflected the

federal tax law in effect as of the time of filing.

2. By Docket Entries dated November 13, 2017, and November 29, 2017, the

Presiding Officers established an agreed procedural schedule which, in relevant part, provided

for the OUCC and Intervenors to file case-in-chief evidence by January 24, 2018, NIPSCO and

other parties to file rebuttal or cross-answering evidence by February 21, 2018, any settlement to

be submitted by February 28, 2018, and an evidentiary hearing to commence on March 14, 2018.

That procedural schedule did not anticipate a need for, or make provision to accommodate, any

submission of supplemental case-in-chief evidence.

3. In December 2017, Congress enacted legislation effectuating a comprehensive

restructuring of federal tax law. The bill commonly referred to as the Tax Cuts and Jobs Act,

H.R. 1, titled “An Act to provide for reconciliation pursuant to titles II and V of the concurrent

resolution on the budget for fiscal year 2018” (the “Act”), became Public Law No. 115-97 on

December 22, 2017. The Act has an effective date of January 1, 2018.

4. The provisions of the Act materially impact the rate relief sought by NIPSCO in

this proceeding. In particular, the Act reduces the federal corporate income tax rate from 35% to

21%. In addition, an array of revisions to federal tax law will or may affect a number of



Page 2 of 7

3

elements with ratemaking significance, including deferred taxes as a component of capital

structure, alterations in available deductions, accounting for recoverable depreciation, treatment

of regulatory assets, and other components bearing on the computation of rates and charges.

5. On January 3, 2018, by order in Cause No. 45032, the Commission commenced

an investigation to review the implications of the revisions to federal tax law on the rates of

Indiana utilities and to determine any appropriate action. The relief sought in this motion,

including the proposed changes in the procedural schedule, would not be inconsistent in any way

with the investigation under Cause No. 45032.

6. The forward-looking test year in this case is the 12-month period ending

December 31, 2018. The changes in federal tax law effective January 1, 2018, therefore, will

govern NIPSCO’s federal tax liability throughout the test year. Those changes should be

accounted for and fully reflected in the determination of just and reasonable rates and charges as

sought in this proceeding.

7. Insofar as the changes in federal tax law have a material bearing on the merits of

the rate proposals put forward by NIPSCO, the burden of moving forward with evidence in this

regard properly falls on NIPSCO. NIPSCO prepared and submitted its case-in-chief evidence

premised on tax assumptions that are no longer accurate. That case-in-chief evidence is deficient

in light of the changed circumstances as to federal taxes. Joint Movants do not suggest there was

any fault on the part of NIPSCO in failing to anticipate and address the changes in federal tax

law that occurred three months after the initial submission occurred in this case. Nevertheless,

the federal tax legislation substantially impacts the merits of the rate relief sought by NIPSCO.

As the petitioner with the burden of proof in this proceeding, and the party that prepared the

schedules reflecting federal tax assumptions that are no longer correct, NIPSCO should now



Page 3 of 7

4

update its evidence in the first instance to reflect the changes in federal tax law that will be in

effect during the test year.

8. Absent revision to the existing procedural schedule, the OUCC and Intervenors

would be placed in the untenable position of having to attempt, by January 24, 2018, to revise

NIPSCO’s schedules and rate computations in order to reflect the altered federal tax law, in

addition to addressing all the other issues raised in NIPSCO’s case-in-chief submission. At that

point, the OUCC and Intervenors would be challenging rate proposals that all parties, including

NIPSCO, know reflect incorrect tax predicates. In that instance, NIPSCO would not offer

evidence revising its proposals in light of the federal tax legislation until its rebuttal submission

on February 21, 2018. All other parties, then, would have no opportunity to offer evidence

responsive to what should be material changes in NIPSCO’s positions.

9. Joint Movants contend the proper approach, accordingly, is to revise the schedule

to make provision for an evidentiary filing by NIPSCO supplementing its case-in-chief evidence,

limited in scope to addressing the impact of the federal tax legislation on the rate relief proposed

by NIPSCO. Joint Movants propose that NIPSCO make that filing by January 24, 2018, the date

currently established for the initial evidentiary submissions of the OUCC and Intervenors. In

light of the potential expansion of issues and need for discovery relating to NIPSCO’s

supplemental filing, Joint Movants propose that the OUCC and Intervenors should file their case-

in-chief evidence by February 28, 2018, with NIPSCO’s rebuttal and any cross-answering

testimony due by March 28, 2018. The deadline for filing any settlement would be April 4,

2018, and the evidentiary hearing would be rescheduled to the earliest available date on the

Commission’s calendar after April 18, 2018.



Page 4 of 7

5

10. In light of the need for a submission by NIPSCO supplementing and revising its

case-in-chief evidence, and the resulting amendment to the procedural schedule, Joint Movants

suggest there is good cause for the Commission to suspend the three hundred (300) day deadline

imposed by Ind. Code §8-1-2-42.7(e), consistent with this revised procedural schedule. Section

42.7(h) permits such a suspension for “good cause.” That statutory provision does not require

any finding of fault or neglect on the part of the petitioning utility. Here, the intervening post-

filing circumstance of federal tax legislation that substantially impacts the merits of the rate relief

sought by NIPSCO warrants a suspension pursuant to Section 42.7(h), in order to allow for the

orderly presentation of evidence relevant to that material change of circumstance.

WHEREFORE, Joint Movants respectfully request that the procedural schedule be

revised as follows: (a) NIPSCO shall file its supplemental evidence, limited to the change in

federal tax law, by January 24, 2018; (b) the OUCC and Intervenors shall file their case-in-chief

evidence by February 28, 2018; (c) NIPSCO shall file its rebuttal evidence and the OUCC and

Intervenors shall file any cross-answering evidence by March 28, 2018; (d) any settlement will

be filed by April 4, 2018; and (e) the evidentiary hearing will be rescheduled to the earliest

available date on the Commission’s calendar after April 18, 2018. In addition, Joint Movants

request that the Commission exercise its authority under Ind. Code §8-1-2-42.7(h) and suspend

the 300-day deadline for a period consistent with this revised procedural schedule.

Respectfully submitted,

LEWIS & KAPPES, P.C. /s/ Todd A. Richardson Todd A. Richardson, Atty No. 16620-49 On behalf of Joint Movants



Page 5 of 7

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CERTIFICATE OF SERVICE The undersigned hereby certifies that a copy of the foregoing has been served upon the

following via electronic mail, this 5th day of January, 2018:

Claudia J. Earls Christopher C. Earle NISOURCE CORPORATE SERVICES – LEGAL 150 West Market Street, Suite 600 Indianapolis, IN 46204 [email protected] [email protected] Kay E. Pashos Steven W. Krohne Philip B. McKiernan ICE MILLER, LLP One American Square, Suite 2900 Indianapolis, IN 46282-0200 [email protected] [email protected] [email protected]; Courtesy copy to: Timothy R. Caister Erin E. Whitehead NORTHERN INDIANA PUBLIC SERVICE

COMPANY 150 West Market Street, Suite 600 Indianapolis, IN 46204 [email protected] [email protected] Joseph P. Rompala Tabitha L. Balzer LEWIS & KAPPES, P.C. One American Square, Suite 2500 Indianapolis, IN 46282-0003 [email protected] [email protected]

Abby R. Gray Randall C. Helmen Tiffany Murray OFFICE OF THE UTILITY CONSUMER

COUNSELOR 115 W. Washington St., Suite 1500 South Indianapolis, Indiana 46204 [email protected] [email protected] [email protected] [email protected] Jennifer A. Washburn Margo L. Tucker CITIZENS ACTION COALITION OF INDIANA, INC. 1915 West 18th Street, Suite C Indianapolis, IN 46202 [email protected] [email protected] Nikki G. Shoultz Kristina Kern Wheeler BOSE MCKINNEY & EVANS LLP 111 Monument Circle, Suite 2700 Indianapolis, IN 46204 [email protected] [email protected] Robert K. Johnson, Esq. 2454 Waldon Drive Greenwood, IN 46143 [email protected]



Page 6 of 7

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Courtesy copy to: Birch Evans Bayh III, Esq. MCGUIREWOODS LLP 2001 K Street N.W. Suite 400 Washington, DC 20006-1040 [email protected]

/s/ Todd A. Richardson Todd A. Richardson LEWIS & KAPPES, P.C. One American Square, Suite 2500 Indianapolis, Indiana 46282-0003 Telephone: (317) 639-1210 Facsimile: (317) 639-4882



Page 7 of 7

MPSC Case No.: U-18419 Respondent: K. J. Chreston/B. J. Marietta Requestor: ABATE Question No.: ABDE-2.7 Page: 1 of 1 Question: Please discuss in detail when the decision to retire the coal plants must be

made in order to comply with the ELG and 316(b) environmental regulations.

Answer: The timing and significance of the ELG and 316(b) environmental

regulations vary at each plant. The current administration has indicated an intent to review and possibly revise the ELG requirements and compliance dates. The EPA issued a final rule September 18, 2017 in which EPA states its intention to review and potentially revise the Bottom Ash Transport Water (BATW) and Flue Gas Desulfurization Wastewater Treatment limits. Considering this review, EPA postponed certain compliance dates from 2018-2023 to 2020-2023. The actual compliance date for a specific facility is determined by the NPDES permitting agency, which is the Michigan Department of Environmental Quality (MDEQ) for the DTE Electric facilities regulated by ELG.

The Company has been working with MDEQ to determine the applicable compliance date for each regulated facility. It is expected that in addition to final compliance dates, ELG milestones will be established within St. Clair, River Rouge and Trenton Channel NPDES permits as they are renewed later this year. The milestones could possibly include a final decision date to retire or begin installation of equipment to achieve zero bottom ash transport water discharge.

Currently there is not a specific date when a decision to retire coal plants must be made in order to comply with these regulations. However, given the uncertainty about the scope and timing of possible revisions to environmental requirements, and also the age of the River Rouge, St. Clair, and Trenton Channel units and the costs to operate them beyond their announced retirements, the Company has concluded, at this point in time, that the most reasonable and prudent plan is to retire these coal-fired units as announced.



Page 1 of 1

216768428.1 07411/319492

STATE OF MICHIGAN


* * * * *

In the matter of the Application ofDTE Electric Company for approval ofCertificates of Necessity pursuant to MCL 460.6s,as amended, in connection with the addition of anatural gas combined cycle generating facility toits generation fleet and for related accounting andratemaking authorizations.

))))))))

Case No. U-18419

ALJ Suzanne D. Sonneborn

PROOF OF SERVICE

STATE OF MICHIGAN )) ss

COUNTY OF OAKLAND )

Robert A. W. Strong, being first duly sworn, deposes and says that on January 12, 2018,

he did cause to be served the Direct Testimony and Exhibits of Nicholas L. Phillips on behalf

of the Association of Businesses Advocating Tariff Equity, as well as this Proof of Service, in

the above docket, via electronic mail, to the persons identified on the attached service list.

____________________________________Robert A. W. Strong

Subscribed and sworn to before methis 12th day of January, 2018.

______________________________________Linda L. McCauley, Notary PublicOakland County, MichiganMy Commission Expires: October 18, 2019Acting in Oakland County

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216768428.1 07411/319492

SERVICE LISTMPSC Case No. U-18419

Administrative Law JudgeSuzanne D. [email protected]

MPSC StaffHeather M. S. DurianAmit T. [email protected]@michigan.gov

Counsel for DTE Electric CompanyDavid S. MaqueraJon P. ChristinidisMichael J. SoloRichard P. MiddletonAndrea E. [email protected]@[email protected]@[email protected]@dteenergy.com

Counsel for Attorney General Bill SchuetteJohn A. JaniszewskiCeleste R. [email protected]@[email protected]

Counsel for Environmental Law & PolicyCenter, Ecology Center, Solar EnergyIndustries Association, Union of ConcernedScientists, and Vote SolarMargrethe [email protected]

Counsel for ABATE:Robert A. W. StrongMichael J. PattwellSean P. GallagherStephen A. CampbellClark Hill [email protected]@[email protected]@clarkhill.com

Counsel for Michigan EnvironmentalCouncil, NRDC and The Sierra ClubChristopher M. BzdokTracy Jane AndrewsLydia [email protected]@[email protected]

Marcia Randazzo, Legal [email protected] Flynn, Legal [email protected]

Consultant for ABATE:Nicholas L. PhillipsJames R. DauphinaisMaria Decker, Admin. AssistantBrubaker & Associates, Inc.P.O. Box 412000St. Louis, MO [email protected]@[email protected]

mailto:[email protected]





















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216768428.1 07411/319492

Counsel for City of Ann Arbor, EnergyMichigan, Inc. and Michigan EnergyInnovation Business CouncilTimothy J. LundgrenLaura A. ChappelleToni L [email protected]@[email protected]

Counsel for International TransmissionCompanyAmy C. MonopoliStephen J. [email protected]@itctransco.com

Counsel for Midland Cogeneration VentureRichard AaronKyle M. AsherJason [email protected]@[email protected]









via electronic case filing ms. kavita kale executive ...ms. kavita kale executive secretary michigan...

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